Downhole Hydrogen Sulfide Capture and Measurement

ABSTRACT

Disclosed herein are methods and systems for capture and measurement of a target component. A fluid sampling tool for sampling fluid from a subterranean formation may include a sample chamber having a fluid inlet, wherein the sample chamber is lined with a coating of a material that can reversibly hold a target component.

BACKGROUND

Wells may be drilled at various depths to access and produce oil, gas,minerals, and other naturally-occurring deposits from subterraneangeological formations. The drilling of a well is typically accomplishedwith a drill bit that is rotated within the well to advance the well byremoving topsoil, sand, clay, limestone, calcites, dolomites, or othermaterials. The drill bit is typically attached to a drill string thatmay be rotated to drive the drill bit and within which drilling fluid,referred to as “drilling mud” or “mud”, may be delivered downhole. Thedrilling mud is used to cool and lubricate the drill bit and downholeequipment and is also used to transport any rock fragments or othercuttings to the surface of the well.

It is often desired to collect a representative sample of formation orreservoir fluids (e.g., hydrocarbons) to further evaluate drillingoperations and production potential, or to detect the presence ofcertain gases or other materials in the formation that may affect wellperformance. For example, hydrogen sulfide (H2S), a poisonous,corrosive, and flammable gas can occur in formation fluids, and itspresence in the wellbore in significant concentrations may result indamage to wellbore components or dangerous conditions for well operatorsat the surface. However, H2S concentration in formation fluids is oftenunderestimated with current measurement techniques, for example, due tolosses via absorption/adsorption on tool surfaces and/or during sampletransfers.

BRIEF DESCRIPTION OF THE DRAWINGS

The features and advantages of certain embodiments will be more readilyappreciated when considered in conjunction with the accompanyingfigures. The figures are not to be construed as limiting any of thepreferred embodiments.

FIG. 1A illustrates a schematic view of a well in which an exampleembodiment of a fluid sample system is deployed.

FIG. 1B illustrates a schematic view of another well in which an exampleembodiment of a fluid sample system is deployed.

FIG. 2 illustrates a schematic view of an example embodiment of a fluidsampling tool.

FIG. 3 illustrates an enlarged schematic view of an example embodimentthe fluid sampling tool of FIG. 2

FIG. 4 illustrates a cross-sectional view an example embodiment of asample chamber coated with a material that is reversibly sorbent.

FIG. 5A illustrates an enlarged cross-sectional view of a sample chambershowing an example embodiment of a porous coating.

FIG. 5B illustrates an enlarged cross-sectional view of a sample chambershowing an example embodiment of a structured coating,

FIG. 6 illustrates an example diagram of an example test system fortarget component measurement.

DETAILED DESCRIPTION

The present disclosure relates to subterranean operations and, moreparticularly, embodiments disclosed herein provide methods and systemsfor capture and measurement of a target component.

Embodiments may include sampling of formation fluids from a wellbore todetermine a concentration of a target component in the formation fluid.Target component may include any of a variety of gases, vapors, orliquids, where quantification in formations fluids may be desired,including, but not limited to, H2S, mercury, and carbon dioxide, amongothers. By way of example, H2S is a volatile chemical that oxidizeseasily, is corrosive to downhole tools, and is poisonous and explosive.The presence of H2S in a formation may increase the cost of extractingand processing formation fluids from a well and also present a safetyhazard to well operators, Accurate measurement of H2S (or other targetcomponents) in the formation fluids can better enable well operators tomake decisions about completing a well so that formation fluids can beeconomically extracted while maintaining safe conditions for welloperators. In addition, it may desirable to know concentration ofmercury and carbon dioxide as well, as these components can also becorrosive.

The fluid sampling tools described herein may vary in design, butembodiments of the fluid sampling tools typically may include an inlet,an outlet, and a sampling chamber. Embodiments may further include twoor more sampling chambers. The inlet and outlet may be fluidly connectedto the fluid within the wellbore that is being extracted from asubterranean formation. In operation, a fluid sample may be gatheredinto the sampling chamber from the wellbore for analysis. Embodimentsmay include coating inner surfaces of the sampling chamber with amaterial that can reversibly sorb the target component. In this manner,the target component in the fluid sample should be sorbed by thecoating, instead of being lost via sorbtion on tool surfaces. At adesired time, for example, after recovery of the sample tool to the wellsurface, the target component can be desorbed and measured. Given aknown volume of formation fluid sampled and amount of target component,the concentration of the target component in the sample can bedetermined. Multiple component measurements from multiple samplechambers (e.g., two or more) may be obtained, for example, toextrapolate to reservoir conditions. The component measurements may beobtained at different times in the wellbore.

The fluid sampling tools, systems and methods described herein may beused with any of the various techniques employed for evaluating a well,including without limitation wireline formation testing (WFT),measurement while drilling (MWD), and logging while drilling (LWD). Thevarious tools and sampling units described herein may be delivereddownhole as part of a wireline-delivered downhole assembly or as a partof a drill string. It should, also be apparent that given the benefit ofthis disclosure, the apparatuses and methods described herein haveapplications in downhole operations other than drilling, and may also beused after a well is completed.

FIG. 1A illustrates a fluid sampling and analysis system 100 accordingto an illustrative embodiment used in a well 102 having a wellbore 104that extends from a surface 108 of the well 102 to or through asubterranean formation 112. While the wellbore 104 is shown extendinggenerally vertically into the subterranean formation 112, the principlesdescribed herein are also applicable to wellbores that extend at anangle through the subterranean formations 112, such as horizontal andslanted wellbores. For example, although FIG. 1A shows wellbore 104 thatis vertical or low inclination, high inclination angle or horizontalplacement of the wellbore 104 and equipment is also possible. Inaddition, it should be noted that while FIG. 1A generally depicts aland-based operation, those skilled in the art should readily recognizethat the principles described herein are equally applicable to subseaoperations that employ floating or sea-based platforms and rigs, withoutdeparting from the scope of the disclosure.

The well 102 is illustrated with the fluid sampling and analysis system100 being deployed in a drilling assembly 114. In the embodimentillustrated in FIG. 1A, the well 102 is formed by a drilling process inwhich a drill bit 116 is turned by a drill string 120 that extends fromthe drill bit 116 to the surface 108 of the well 102. The drill string120 may be made up of one or more connected tubes or pipes, of varyingor similar cross-section. The drill string 120 may refer to thecollection of pipes or tubes as a single component, or alternatively tothe individual pipes or tubes that include the string. The term “drillstring” is not meant to be limiting in nature and may refer to anycomponent or components that are capable of transferring rotationalenergy from the surface of the well to the drill bit. In severalembodiments, the drill string 120 may include a central passage disposedlongitudinally in the drill string 120 and capable of allowing fluidcommunication between the surface 108 of the well 102 and downholelocations.

At or near the surface 108 of the well 102, the drill string 120 mayinclude or be coupled to a kelly 128. The kelly 128 may have a square,hexagonal, octagonal, or other suitable cross-section. The kelly 128 maybe connected at one end to the remainder of the drill string 120 and atan opposite end to a rotary swivel 132. As illustrated, the kelly 120may pass through a rotary table 136 that is capable of rotating thekelly 128 and thus the remainder of the drill string 120 and drill bit116. The rotary swivel 132 should allow the kelly 128 to rotate withoutrotational motion being imparted to the rotary swivel 132. A hook 138,cable 142, traveling block (not shown), and hoist (not shown) may beprovided to lift or lower the drill bit 116, drill string 120, kelly 128and rotary swivel 132. The kelly 128 and swivel 132 may be raised orlowered as needed to add additional sections of tubing to the drillstring 120 as the drill bit 116 advances, or to remove sections oftubing from the drill string 120 if removal of the drill string 120 anddrill bit 116 from the well 102 is desired.

A reservoir 144 may be positioned at the surface 108 and holds drillingfluid 148 for delivery to the well 102 during drilling operations. Asupply line 152 may fluidly couple the reservoir 144 and the innerpassage of the drill string 120. A pump 156 may drive the drilling fluid148 through the supply line 152 and downhole to lubricate the drill bit116 during drilling and to carry cuttings from the drilling process backto the surface 108. After traveling downhole, the drilling fluid 148returns to the surface 108 by way of an annulus 160 formed between thedrill string 120 and the wellbore 104. At the surface 108, the drillingmud 148 may returned to the reservoir 144 through a return line 164. Thedrilling mud 148 may be filtered or otherwise processed prior torecirculation through the well 102.

FIB. 1B illustrates a schematic view of another embodiment of well 102in which an example embodiment of fluid analysis system 100 may bedeployed. As illustrated, fluid analysis system 100 may be deployed aspart of a wireline assembly 115, either onshore of offshore. Asillustrated, the wireline assembly 115 may include a winch 117, forexample, to raise and lower a downhole portion of the wireline assembly115 into the well 102, As illustrated, fluid analysis system 100 mayinclude fluid sampling tool 170 attached to the winch 117. In examples,it should be noted that fluid sampling tool 170 may not be attached to awinch unit 104. Fluid sampling tool 170 may be supported by rig 172 atsurface 108.

Fluid sampling tool 170 may be tethered to the winch 117 throughwireline 174. While FIG. 1B illustrates wireline 174, it should beunderstood that other suitable conveyances may also be used forproviding mechanical conveyance to fluid sampling tool in the well 102,including, but not limited to, slickline, coiled tubing, pipe, drillpipe, drill string, downhole tractor, or the like. In some examples, theconveyance may provide mechanical suspension, as well as electricalconnectivity, for fluid sampling tool 170. Wireline 174 may include, insome instances, a plurality of electrical conductors extending fromwinch 117. By way of example, wireline 174 may include an inner core ofseven electrical conductors (not shown) covered by an insulating wrap.An inner and outer steel armor sheath may be wrapped in a helix inopposite directions around the conductors. The electrical conductors maybe used for communicating power and telemetry downhole to fluid samplingtool 170.

With reference to both FIGS. 1A and 1B, operation of fluid sampling tool170 for sample collection will now be described in accordance withexample embodiments. Fluid sampling tool 170 may be raised and loweredinto well 102 on drill string 120 (FIG. 1A) and wireline 174. (FIG. 1B).Fluid sampling tool 170 may be positioned downhole to obtain fluidsamples from the subterranean formation 112 for analysis. The formationfluid and, thus the fluid sample may be contaminated with, or otherwisecontain, the target component. In some embodiments, the target componentmay be contained in the fluid sample in small quantities, for example,less than 500 parts per million (“ppm”). For example, the targetcomponent mar be present in the fluid sample in an amount from about 1ppm to about 500 ppm, about 100 ppm to about 200 ppm, about 1 ppm toabout 100 ppm, or about 5 to about 10 ppm. The fluid sampling tool 170may be operable to measure, process, and communicate data regarding thesubterranean formation 112, fluid from the subterranean formation 112,or other operations occurring downhole. After recovery, the fluid samplemay be analyzed, for example, to quantify the concentration of thetarget component. This information, including information gathered fromanalysis of the fluid sample, allows well operators to determine, amongother things, the concentration the target component within the fluidbeing extracted from the subterranean formation 112 to make intelligentdecisions about ongoing operation of the well 102. In some embodiments,the data measured and collected by the fluid sampling tool 170 mayinclude, without limitation, pressure, temperature, flow, acceleration(seismic and acoustic), and strain data. As described in more detailbelow, the fluid sampling tool 170 may include a communicationssubsystem, including a transceiver for communicating using mud pulsetelemetry or another suitable method of wired or wireless communicationwith a surface controller 184. The transceiver may transmit datagathered by the fluid sampling tool 170 or receive instructions from awell operator via the surface controller 184 to operate the fluidsampling tool 170.

Referring now to FIG. 2, an example embodiment of a fluid sampling tool170 is illustrated as a tool for gathering fluid samples from aformation for subsequent analysis and testing. It should be understoodthat the fluid sampling tool. 170 shown on FIG. 2 is merely illustrativeand the example embodiments disclosed herein may be used with other toolconfigurations. In an embodiment, the fluid sampling tool 170 includes atransceiver 202 through which the fluid sampling tool 170 maycommunicate with other actuators and sensors in a conveyance drillstring 120 on FIG. 1A or wireline 174 on FIG. TB), the conveyance'scommunications system, and with a surface controller (surface controller184 on FIG. 1A). In an embodiment, the transceiver 202 is also the portthrough which various actuators (e.g. valves) and sensors (e.g.,temperature and pressure sensors) in the fluid sampling tool 170 arecontrolled and monitored by, for example, a computer in another part ofthe conveyance or by the surface controller 184. In an embodiment; thetransceiver 202 includes a computer that exercises the control andmonitoring function.

The fluid sampling tool 170 may include a dual probe section 204, whichextracts fluid from the formation (e.g., formation 112 on FIGS. 1A and1B), as described in more detail below, and delivers it to a channel 206that extends from one end of the fluid sampling tool 170 to the other.The channel 206 can be connected to other tools or portions of the fluidsampling tool 170 arranged in series. The fluid sampling tool 170 mayalso include a gauge section 208, which includes sensors to allowmeasurement of properties, such as temperature and pressure, of thefluid in the channel 206. The fluid sampling tool 170 may also include aflow-control pump-out section 210, which includes a pump 212 for pumpingfluid through the channel 206. The fluid sampling tool 170 also includesone or more chambers, such as multi-chamber sections 214, which aredescribed in more detail below.

In some embodiments, the dual probe section 204 includes two probes 218,220 which extend from the fluid sampling tool 170 and press against theborehole wall to receive fluid for sampling. Probe channels 222, 224connect the probes 218, 220 to the channel 206. The pump 212 can be usedto pump fluids from the reservoir, through the probe channels 222, 224and to the channel 206. Alternatively, a low volume pump 226 can be usedfor this purpose. Two standoffs or stabilizers 228, 230 hold the fluidsampling tool 170 in place as the probes 218, 220 press against theborehole wall to receive fluid. In an embodiment, die probes 218, 220and stabilizers 228, 230 are retracted when the tool is in motion andare extended to gather samples of fluid from the formation.

With additional reference to FIG. 3, the multi-chamber sections 214include multiple sample chambers 230, While FIGS. 2 and 3 show themulti-chamber sections 214 having three sample chambers 230, it will beunderstood that the multi-chamber sections 214 can have any number ofsample chambers 230 and may in fact be single chamber sections. In someembodiments, the sample chambers 230 may be coupled to the channel 206through respective chamber valves 320, 325, 330. Formation fluid can bedirected from the channel 206 to a selected one of the sample chambers230 by opening the appropriate one of the chamber valves 320, 325, 330.The valves 320, 325, 330 may be configured such that when one of thechamber valves 320, 325, 330 is open the others are closed.

In some embodiments, the multi-chamber sections 214 may include a path335 from the channel 206 to the annulus 160 through a valve 340. Valve340 may be open during the draw-down period when the fluid sampling tool170 is clearing mud cake, drilling mud, and other contaminants into theannulus before clean formation fluid is directed to one of the samplechambers 230. A check valve 345 may prevent fluids from the annulus 160from flowing hack into the channel 206 through the path 335. As such,the mufti-chamber sections 214 may include a path 350 from the samplechambers 230 to the annulus 160.

FIG. 4 illustrates a cross-sectional view an example embodiment of asample chamber 230 lined with a coating 400 of a material that canreversibly sorb a target component. As illustrated, the coating 400 maybe disposed on inner surfaces 402 of chamber walls 404. Sample chamber230 may be any suitable chamber for use in a fluid sampling tool (e.g.,fluid sampling tool 170 on FIGS. 1A, 11B, and 2). In some embodiments,sample chamber 230 may have a fixed volume. For example, the samplechamber 230 may have a fixed volume of from about 0.1 milliliters toabout 1 liter. Alternatively, the sample chamber 230 may have a fixedvolume of from about 1 milliliters to about 1 liter. In someembodiments, the sample chamber 230 may be configured for obtainingmicro-samples, i.e., volumes of less than 1 milliliter. For example, thesample chamber 230 may have a fixed volume of from about 10 millilitersto about 1 milliliters. One of ordinary skill in the art, with thebenefit of this disclosure, should be able to select an appropriatesample chamber 230 and size thereof for a particular application.

As illustrated, the coating 400 may line the sample chamber 230. Thecoating 400 may include any of a variety of suitable materials capableof reversibly sorbing a target component, such as H2S, mercury, orcarbon dioxide, whether by absorption or adsorption. Non-limitingexamples of suitable materials may include, but are not limited to,gold, silver, nickel, platinum, and combinations thereof. In someembodiments, gold may be suitable for reversible absorption of targetcomponent, such as H2S and mercury. In some embodiments, nickel and/orplatinum may be suitable for reversible absorption of H2S and/ormercury. One of ordinary skill in the art, with the benefit of thisdisclosure, should be able to select an appropriate material for thecoating 400 based on a number of factors, including the particulartarget component of interest.

The coating 400 on the chamber walls 404 may have any suitablethickness. For example, the coating 400 may have a thickness of about 10nm to about 100 microns. In some embodiments, the coating 400 may have athickness of about 0.1 micron to about 1 micron or about 10 microns toabout 100 microns. One of ordinary skill in the art, with the benefit ofthis disclosure, should be able to select an appropriate thickness forthe coating 400 based on a number of factors, including the particulartarget component of interest and surface area.

The coating 400 may be applied to the chambers walls 404 using anysuitable technique. Suitable techniques may include any of a variety ofdifferent techniques for depositing a coating onto a substrate,including, but not limited to thin-film deposition techniques, such asatomic layer deposition, physical vapor deposition, and chemical vapordeposition. One or ordinary skill in the art, with the benefit of thisdisclosure, should be able to select an appropriate technique forapplication of the coating 400.

It should be understood that the surface area of the coating 400available for the target component may provide an upper limit on theamount of the target component that can be quantified. In other words,the fluid sample may, in some embodiments, contain more of the targetcomponent than can be sorbed by the coating 400. Accordingly, thesurface of the coating 400 may be selected so that a sufficient quantityof target component can be measured to provide desirable information.

In some embodiments, the surface-to-volume ratio of the coating 400 andor the chamber walls 404 may be maximized, for example, to provideadditional surface area for sorption of the target component. In thismanner, the coating 400 and/or the chamber walls 404 may be configuredto effective sorption of different concentrations of the targetcomponent. In some embodiments, the surface-to-volume ratio of thecoating 400 may be maximized. In some embodiments, the surface-to-volumeratio of the chamber walls 404 may be maximized. In some embodiments,the surface-to-volume ratio of the coating 400 and the chamber walls 404may be maximized. Any of a variety of techniques may be applied to thecoating 400 and/or chamber walls 404 for maximization of thesurface-to-volume ratio. Suitable examples of the coating 400 and/orchamber walls 404 with increased surface-to-volume ratio may includecreation of a porous or structure coating that maximizessurface-to-volume ratio. Examples of suitable techniques formaximization of the surface-to-volume ratio may include, but are notlimited to, lithograph techniques, such as etching, anodizing, orpatterning. Specific examples of suitable lithograph techniques mayinclude, but are not limited to, electro-chemical anodization,semiconductor lithography, and electron-beam lithography. In addition tolithographic techniques applied to the chamber walls 404 and/or thecoating 400 after deposition, techniques may also be used to maximizethe surface-to-volume ratio during of the coating 400 application,including nanotube deposition and nanoparticle deposition. In additionto the above mentioned techniques, the coating material may be depositedin such a way as to create a highly porous material coating.

FIG. 5A illustrates an enlarged cross-sectional view of a sample chamber230 showing an example embodiment of a porous coating 500. The porouscoating 500 may provide, for example, an increased surface-to-volumeratio as compared to non-porous coatings. As illustrated, the porouscoating 500 may be deposed on the inner surfaces 402 of the chamberwalls 404. While the porous coating 500 is shown with a randomdistribution of pores 502, it should be understood that the structureand arrangement of the pores 502 should depend on the particularapplication technique. For example, a porous coating 500 be providedwith the pores 502 in a regular distribution (not shown).

FIG. 5B illustrates an enlarged cross-sectional view of a sample chamber230 showing an example embodiment of a structured coating 504. Thestructured coating 504 may provide, for example, an increasedsurface-to-volume ratio as compared to non-patterned coating. Asillustrated, the structured coating 504 may be deposed on the innersurfaces 402 of the chamber walls 404.

In some embodiments, a protective coating (not shown) may be applied tosample chamber 230 and/or to other components of the fluid sampling tool170. For example, the protective coating may be applied on the chamberwalls 404 underneath the coating 400 such that the coating 400 may bebacked by the protective coating. In addition, the protective coatingmay be applied to other components of the fluid sampling tool 170, suchas o-rings, seals, inlet lines (e.g., channel 206 on FIG. 2), inletvalves (e.g., chamber valves 320, 325, 330 on FIG. 3). The protectivecoating may include any suitable material that is resistant to targetcomponent, for example, does not readily adsorb, absorb, or otherwisereact to the target component. Suitable materials may include, but arenot limited to, aluminum oxide and beryllium oxide, which are bothresistant to H2S. One or ordinary skill in the art, with the benefit ofthis disclosure, should recognize that the specific material for theprotective coating should depend on a number of factors, including theparticular target component.

FIG. 6 illustrates an example of a test system 600 for target componentmeasurement. As illustrated, the test system 600 may include a chamberhousing 602, a fluid analyzer 604, a vacuum pump 606, and a processor608. Chamber housing 602 may include a chamber receptacle 610 forreceiving the sample chamber 230. Sample chamber 230 may contain, forexample, a fluid sample of a formation fluid. In some embodiments, thefluid sample may be evacuated from the sample chamber 230 prior to useof test system 600. As previously described, the fluid sample maycontain a target component. It may be desired to quantity theconcentration of the target component in the fluid sample. In someembodiments, test system 600 may be used for measurement andquantification of the target component in the fluid sample.

In some embodiments, the chamber housing 602 may receive the samplechamber 230 in the chamber receptacle 610. As previously described, thetarget component may have been sorbed by the coating (e.g., coating 400on FIG. 4) lining the sample chamber 230. The chamber housing 602 may beoperable to desorb the target component from the coating. By way ofexample, the chamber housing 602 may include a heating element 612. Insome embodiments, the heating element 612 may confirm electrical energyinto heat. The heat from the heating element 612 may heat the chamberhousing 602 such that the target component may be desorbed from thechamber housing 602. While the heating element 612 is shown, it shouldbe understood that the present techniques are intended to encompassother techniques for desorption of the target component from the chamberhousing 602. For example, the target component may be chemicallystripped from the chamber housing 602.

Test system 600 may further include a fluid analyzer 604 for analyzingthe target component after desorption from the chamber housing 602. Inthe illustrated embodiment, a channel 614 provides fluid communicationbetween the fluid analyzer 604 and the sample chamber 230. Chamberhousing 602 may be opened (or otherwise) accessed so that the desorbedtarget component in the chamber housing 602 can be provided into thefluid analyzer 604 for analysis. As illustrated, a vacuum pump 606 maybe used, for example, to create a suction that drives the fluid samplewith the desorbed target component from the chamber housing 602 to thefluid analyzer 604. Fluid analyzer 604 may use any of a variety ofsuitable analysis techniques for analyzing the fluid sample to quantifyconcentration of the target component. Suitable analysis techniques mayinclude, but are not limited to, gas chromatography, mass spectrometry,and optical sensors.

Test system 600 may further include processor 608. The processor 608 mayinclude any suitable device for processing instructions, including, butnot limited to, a microprocessor, microcontroller, embeddedmicrocontroller, programmable digital signal processor, or otherprogrammable device. The processor 608 may also, or instead, be embodiedin an application specific integrated circuit, a programmable gatearray, programmable array logic, or any other device or combinations ofdevices operable to process electric signals. The processor 608 may becommunicatively coupled to the fluid analyzer 604. The connectionbetween the fluid analyzer 604 and the processor 608 may be a wiredconnection or a wireless connection, as desired for a particularapplication.

In some embodiments, the processor 200 can be configured to receiveinputs from the fluid analyzer 604, for example, to determine aconcentration of the target component in the fluid sample. The fluidanalyzer 604, for example, may measure a total quantity (e.g., volume,moles, etc.) of the target component. Since of a total volume of thefluid sample in the sample chamber is known, the concentration of thetarget component in the fluid sample can then be readily determined withthe total quantify of the target component.

In some embodiments, target component measurements may be extrapolatedto reservoir conditions. Extrapolation may be performed, for example,using measurements of the target component from more than one samplechamber 230. The fluid sample may be acquired in each of the more thanone sample chamber 230 downhole at during the same pump out or atdifferent times. Any suitable technique may be used for extrapolatingthe target component measurement to reservoir conditions, including, butnot limited to, equations of state and geodynamic modeling, amongothers.

Accordingly, this disclosure describes methods and systems for captureand measurement of a target component. Without limitation, the systemsand methods may further be characterized by one or more of the followingstatements:

Statement 1. A fluid sampling tool for sampling fluid from asubterranean formation may be provided. The fluid sampling tool mayinclude a sample chamber having a fluid inlet, wherein the samplechamber is lined with a coating of a material that can reversibly hold atarget component.

Statement 2. The fluid sampling tool of statement 1, wherein the fluidsampling tool further includes a probe that is extendable to engage thesubterranean formation from a wellbore, a pump coupled to the probe forpumping fluid from the subterranean formation, wherein the samplechamber is coupled to the pump for receiving a fluid sample pumped fromthe subterranean formation through the probe.

Statement 3. The fluid sampling tool of statement 1 or 2, furtherincluding more than one of the sample chamber.

Statement 4. The fluid sampling tool of any preceding statement, whereinthe sample chamber includes a sample fluid including the targetcomponent.

Statement 5, The fluid sampling tool of any preceding statement, whereinthe target component includes at least one component selected from thegroup consisting of hydrogen sulfide, mercury, carbon dioxide, andcombinations thereof, and wherein the material includes at least onematerial selected from the group consisting of gold, aluminum oxide,nickel, platinum, and combinations thereof.

Statement 6. The fluid sampling tool of any preceding statement, whereinthe coating and/or one or more walls of the sample chamber were treatedto increase a surface-to-volume ratio of the coating.

Statement 7. The fluid sampling tool of statement 6, wherein coatingand/or the one or more walls were treated with a treatment including atleast one lithographic technique selected from the group consisting ofetching, anodizing, patterning, and combinations thereof.

Statement 8. The fluid sampling tool of any preceding statement, whereinat least one surface of the fluid sampling tool is coated with aprotective coating that is resistant to the target component.

Statement 9. The fluid sampling tool of any preceding statement, whereinthe coating is a porous or structured coating.

Statement 10. The fluid sampling tool of any preceding statement,wherein the coating includes gold, wherein the target component includeshydrogen sulfide, and wherein at least one surface of the fluid samplingtool is coated with a protective coating of aluminum oxide that isresistant to the target component.

Statement 11. The fluid sampling tool of any preceding statement,wherein the material is backed with an inert material to the targetcomponent.

Statement 12. The fluid sampling tool of statement 11, wherein the inertmaterial includes aluminum oxide, beryllium oxide, or a combinationthereof.

Statement 13. A method for sampling formation fluids may be provided.The method may include inserting a sample chamber into a wellbore,wherein the sample chamber is lined with a material that can reversiblyhold a target component. The method may further include collecting afluid sample in the sample chamber while disposed in the wellbore suchthat the target component in the fluid sample is at least partiallysorbed by the material.

Statement 14. The method of statement 13, wherein at least 99% by volumeof the target component in the fluid sample is sorbed by the material.

Statement 15. The method of statement 13 or 14, further includingretrieving the sample chamber from the wellbore, desorbing the targetcomponent from the material, and measuring a quantity of the desorbedtarget component.

Statement 16. The method of statement 15, wherein the desorbing includesheating the sample chamber.

Statement 17. The method statement 15 may further include collecting oneor more additional fluid samples in one or more additional samplechambers while disposed in the wellbore, wherein the one or moreadditional sample chambers are lined with the material such that atleast a portion of the target component present in the one or moreadditional fluid samples is at least partially sorbed by the material inthe one or more additional sample chambers. The method may furtherinclude retrieving the one or more additional sample chambers from thewellbore. The method may further include desorbing the target componentfrom the material in the one or more additional samples chambers. Themethod may further include measuring a quantity of the desorbedcomponent from the one or more additional sample chambers. The methodmay further include extrapolating the quantity of the desorbed componentfrom the one or more additional sample chambers and the desorbedcomponent from the sample chamber to a reservoir concentration.

Statement 18, The method of any one of statements 13 to 17, wherein thetarget component includes hydrogen sulfide and the material includesgold, and wherein at least one surface of a fluid sampling toolincluding the sample chamber is partially coated with a protectivecoating that is resistant to the target component.

Statement 19. A test system for component measurement may be provided.The test system may include a chamber housing including a chamberreceptacle for receiving a sample chamber. The test system may furtherinclude a heating element disposed in the chamber housing arranged toheat the sample chamber. The test system may further include a fluidanalyzer for measuring a desorbed component from the sample chamber. Thetest system may further include a vacuum pump in fluid communicationwith the chamber housing for creating a suction to transfer the desorbedcomponent from the sample chamber to the fluid analyzer. The test systemmay further include a processor operable to receive inputs from thefluid analyzer to determine a concentration of the desorbed component.

Statement 20. The system of statement 19, wherein the fluid analyzer isselected from a mass spectrometer, a gas chromatograph, an opticalsensor, and combinations thereof.

The preceding description provides various embodiments of the systemsand methods of use disclosed herein which may contain different methodsteps and alternative combinations of components. It should beunderstood that, although individual embodiments may be discussedherein, the present disclosure covers all combinations of the disclosedembodiments, including, without limitation, the different componentcombinations, method step combinations, and properties of the system. Itshould be understood that the compositions and methods are described interms of “including,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. Moreover, the indefinitearticles “a” or “an,” as used in the claims, are defined herein to meanone or more than one of the element that it introduces.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present embodiments are well adapted to attain the endsand advantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, and may bemodified and practiced in different but equivalent manners apparent tothose skilled in the art having the benefit of the teachings herein.Although individual embodiments are discussed, the disclosure covers allcombinations of all of the embodiments. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. Also, the terms in the claimshave their plain, ordinary meaning unless otherwise explicitly andclearly defined by the patentee. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of those embodiments. If there is any conflict in the usages of aword or term in this specification and one or more patent(s) or otherdocuments that may be incorporated herein by reference, the definitionsthat are consistent with this specification should be adopted.

What is claimed is:
 1. A system comprising: a chamber housing comprisinga chamber receptacle for receiving a sample chamber; a pump in fluidcommunication with the chamber housing for creating a pressure to drivea target component from the sample chamber to an analytical technique;and a processor operable to receive inputs from the analytical techniqueto determine a concentration of the target component.
 2. The system ofclaim 1, wherein the analytical technique is a fluid analyzer.
 3. Thesystem of claim 2, wherein the fluid analyzer is selected from a massspectrometer, a gas chromatograph, an optical sensor, and combinationsthereof.
 4. The system of claim 1, wherein the analytical techniquemeasures a desorbed component.
 5. The system of claim 1, wherein theanalytical technique is a gas chromatography, a mass spectrometry, or anoptical sensor.
 6. The system of claim 1, further comprising a heatingelement disposed in the chamber housing arranged to heat the samplechamber.
 7. The system of claim 6, wherein the heating element providesheat electrically or chemically.
 8. The system of claim 1, wherein thepump is a vacuum pump or a low volume pump.
 9. The system of claim 1,wherein the sample chamber holds micro-samples.
 10. The system of claim1, wherein the target component is desorbed in the sample chamber.
 11. Amethod comprising: inserting a target component into a sample chamber;driving the target component from the sample chamber to an analyticaltechnique using a pump; and identifying a concentration of the targetcomponent using a processor; and extrapolating a quantity of the targetcomponent to a reservoir concentration.
 12. The method of claim 11,further comprising desorbing the target component in the sampleschamber.
 13. The method of claim 11, wherein the analytical technique isa fluid analyzer.
 14. The method of claim 13, wherein the fluid analyzeris selected from a mass spectrometer, a gas chromatograph, an opticalsensor, and combinations thereof.
 15. The method of claim 11, whereinthe analytical technique measures a desorbed component.
 16. The methodof claim 11, wherein the analytical technique is a gas chromatography, amass spectrometry, or an optical sensor.
 17. The method of claim 11,further comprising a heating element to heat the sample chamber.
 18. Themethod of claim 17, wherein the heating element provides heatelectrically or chemically.
 19. The method of claim 11, wherein the pumpis a vacuum pump or a low volume pump.
 20. The method of claim 11,wherein the sample chamber holds micro-samples.